1. Field of the Invention
This invention relates broadly to the hydrocarbon industry. More particularly, this invention relates to methods and apparatus for the real-time interpretation of data from a downhole flow meter for multiphase mixtures in a hydrocarbon well.
2. State of the Art
The measurement of oil, water, and gas flow rate in each producing zone of an oil well is important to the monitoring and control of fluid movement in the well and reservoir. In addition to a flow meter, each zone may have a valve to control the fluid inlet from that zone. By monitoring flow rates of oil and water from each zone and reducing flow from those zones producing the highest water cut (i.e., ratio of water flow rate to total flow rate), the water production of the entire well can be controlled. This allows the reservoir oil to be swept more completely during the life of the well. In addition, by monitoring flow rates of oil and water from particular zones, zonal allocation of the oil production can be controlled.
Ideally, a flow meter in such an installation should satisfy several criteria:                1) it should be extremely reliable and operate for years at downhole temperatures and pressures;        2) it should operate in both stratified (near-horizontal) and dispersed flow regimes over a wide range of total flow rate and cut;        3) it should not require that the completion be oriented azimuthally in any particular way during installation;        4) it should not require licensing of radioactive sources; and        5) it should allow small changes in water cut and flow rate to be detected.        
Co-owned British Patent GB2351810 (International Publication Number WO 00/68652), the complete disclosure of which is hereby incorporated by reference herein, discloses a method and apparatus for determining the flow rates of fluid phases in a pipe containing multiple fluid phases (e.g. oil, water, and gas). A Venturi is provided to measure total volumetric flow rate measurement and a holdup measurement is taken at a location 0-20 (and preferably 3-10) pipe diameters downstream of the Venturi. In a producing well, the volume fraction of a specific fluid phase in the upward moving flow stream is called “holdup” (e.g., water holdup, oil holdup). The relative quantities of the fluids produced at the surface are related to the holdup and upward velocity of each phase. The holdup measurement is made at a downstream location where a substantial amount of mixing occurs and the difference between the velocities of the fluid phases can effectively be ignored. The flow rates of the phases can thus be determined directly from the holdup measurements. The apparatus disclosed is referred to as the “Flow Watcher Densitometer” or “FWD” (a trademark of Schlumberger).
Prior art FIG. 7 is a schematic view of the FWD. The FWD combines a Venturi 110 with a simple gamma-ray attenuation density measurement. A differential pressure sensor 130 measures the pressure drop between the inlet 112 (at port 132) and the Venturi throat 116 (at port 134). A flow instability develops as the flow exits from the Venturi diffuser 118. A source of gamma-rays 142 is provided which is preferably 133Ba, (although 137CS or other isotopes can also be used). A gamma-ray detector 144, preferably an NaI (Tl) scintillation detector, is placed diametrically opposite the source 142. The gamma-ray source 142 and detector 144 are preferably placed at a particular location which is a distance 0-20 times (and preferably 3-10 times) the downstream pipe diameter 124. With no fluid in the pipe, gamma-rays from the source travel across the pipe and are detected in the gamma-ray detector with a certain rate Rs. With fluid in the pipe, the gamma-rays are scattered and absorbed according to the density of the fluid, with the result that the detection rate R is reduced according to Equation (1) for typical borehole fluids:R=Rse−τρd  (1)where d is the diameter of the pipe, ρ is the average density of fluid along the path between source and detector, and τ is the mass attenuation coefficient, which is essentially constant.
Equation (1) may be used to calibrate the device (i.e., determine Rs) with a known fluid such as water. Thus, the average oil holdup or water holdup of a mixture of oil and water along the attenuation path of the gamma-rays (across the diameter of the pipe) can be calculated from the mixture density. This holdup, which is the average along the attenuation path, is equal to the pipe area averaged holdup because the oil and water are mixed relatively thoroughly throughout the pipe cross-section. It has been found on the basis of flow loop experiments that this condition is satisfied approximately 3-10 pipe diameters downstream of the downstream end of the Venturi diffuser even if the flow entering the Venturi is stratified. However, a substantial improvement in the accuracy of determining the relative flow rates of water and oil can be obtained under some circumstances by measuring the holdup at any location from just downstream of the Venturi to about 20 pipe diameters away. For example, it may be sufficiently accurate to measure the holdup at locations where the stratification has been significantly perturbed.
Thus, the FWD combines a Venturi with a gamma ray mixture density measurement at a particular spacing downstream from the Venturi. Over a wide range of flow rates, the spacing assures a well mixed flow with essentially no slip between oil, water or gas phases. This is a major improvement over most other downhole flow meters because no slip-model is needed to translate measured holdup into cut. In two-phase conditions, either gas/liquid or water/oil, the gamma ray measurement (properly calibrated) will provide cut directly and, when combined with the Venturi ΔP measurement, will provide individual-phase flow rates. The interpretation of three-phase flow is more complicated, however.